Good afternoon, ladies and gents. I'm the Security Manager for the [indiscernible]. I just want to have a quick brief on fire regulations over here. Just to let you know that we do not have any fire drills on for today. Also to let you know that should you hear the alarm, we have a 2-stage alarm, that we have to go and investigate the alarm first. And then when you hear the second alarm and if it's a continuous alarm, then we have members of our team who will be escorting you out accordingly. Okay. Thank you very much.

Peter R. Voser

Thank you very much. Great. Welcome to the Royal Dutch Shell Second Quarter 2012 Results Presentation. So Simon and I will take you through the results and update you on where we are with our strategy. And then there will be plenty of time for questions at the end. We'll take questions here from the room, but also from the web.

Obviously, you know the drill in this one. Let me start with the overview, the global economy. Again the energy markets are likely to see continued high volatility. This is really an interplay between structural growth in energy demand and on the other side, some unprecedented geopolitical events, such as we see playing out in the Eurozone at the moment, Arab Spring comes to mind and the others.

Now this is a very complex landscape for us in the energy industry and in a highly interconnected world, therefore, we see a lot of opportunities for a global integrated company like Shell. We are on track for our cash flow targets of up to $200 billion for 2012 to '15, which as you know, is some 50% higher than the previous 4 years. And we're also on track for oil and gas production of some 4 million barrels of oil equivalent per day in 2017 and '18, the outcome of our investment decisions and financial targets.

Now this is an ambitious program and we have got lots to do. So let me, over the next few minutes, update on where we are with our progress on all of this. Our Q2 2012 CCS earnings, including -- excluding identified items, were $5.7 billion or $13 billion for the first half. Now in the second quarter, we had a lot of planned maintenance, actually, as some of it we have indicated, and we also had some timing issues on dividend payments, that together was roughly $500 million, which you need to take into account when you look at our clean earnings.

Now we are seeing the impact of the weaker economy in our results. We sold $4 billion of assets in the first 6 months of the year, as we improve Shell's capital efficiency from -- and we form strategic partnerships and upgrade the portfolio.

The underlying Upstream volumes were good. They were up 4%. We have new projects under construction for medium-term growth, making deliberate top down choices with our investments, where we can add value with technology, with integration and the scale of Shell.

Now we're also working hard to get choice into our portfolio with new exploration acreage and new integrated gas opportunities crystallizing in 2012, and I'll come back to that with a slide later on. So it has been a busy time and still is a busy time in 2012, and I will give you now some more details on the issues which we're working on.

First let me start with continuous improvement. We are working on these programs across the company and the opportunities, they run actually into the billions of the dollars from a potential point of view. In Downstream, for example, where industry returns are likely to remain under pressure for some time, we have put a lot of work into reducing our unplanned downtime in our refineries and chemical plants. There's clearly more to come here, but I'm -- what we have seen so far are very positive trends. This is actually the first half unplanned downtime at historically low levels and the top quartile industry performance.

The Port Arthur refinery expansion project on the Gulf Coast, which had crude distillation unit damage shortly after startup, is not yet in the figures on this chart. The Motiva joint venture, which runs this plant, expects the crude units restarts to be delayed into 2013. Now let me just be clear, we are not happy with this. And we are investigating and we're working hard to turn this around and actually learn out of the incident.

On the Upstream side, we are coming to the end of the ramp-up of the 3 large projects we have been working for the last 6 years or so. Qatar LNG and GTL and Canada Oil Sands, and I think many of you have been visit -- have had the chance to visit these assets. Large scale, taking low Upstream volumes into end-user products markets major investments as infrastructure and technology.

These are all the seams [ph] where Shell adds a lot of value. Now Qatargas 4 energy achieved full production in 2011 and it has already delivered 9.8 million tonnes of LNG in 11 countries.

AOSP expansion one in oil sands Canada has been operating at all quality adjusted design rates in the second quarter. Pearl Gas-to-Liquids has already produced 4.5 million tonnes of NGLs and GTL products, and both trains have run at 90% to 100% of design rates. This is a great achievement and Pearl is one of a kind of an asset. And some of you, or most of you, have seen it as well.

Now we have already learned a lot about this facility, which gives us new opportunities for continuous improvements. Maintenance, started in the second quarter, will continue during the third quarter, impacting production with minor modifications as we get both GTL trains and the utilities running as a single integrated asset. This is all building up to the final slate and marketing the higher-value products of what I call the Downstream side of the project, essentially a gas-based refinery.

Now I want to change the emphasis here. The last 6 years have been all about the construction and ramp-up phase of these exciting projects. Going forward on these 3, it's all about safe and reliable production operations, getting more out of the assets from things like debottlenecking of oil sands for example, catalyst improvements, more product placed in high-value specialty markets and petrochemicals opportunities in Qatar and maximizing commercial returns in the integrated value chains on all of these projects.

So you might hear less about them in our presentations, but they are going to be important drivers of the results. First half 2012 production from these 3 was 360,000 BOE per day, compared to 184 per day in the first half of '11. They generated $2.7 billion or 12% of the first half of our CFFO, cash flow from operations, and $1.8 billion or 14% of first-half earnings.

I think if you look at Shell's growth profile in the last few years, the investment profile was really dominated by Qatar and by Canada. Now there is an important shift in our project flow here because these 3 are now onstream, with a large number of projects driving the next wave of growth. This, of course, diversifies shareholder risk compared to the position in the last few years.

Some 60% of our Upstream spending this year, for example, is in North America and in Australia. We have around 8 billion barrels of resources under construction, over 20 projects underway, and more than 30 more on the drawing board to sustain our growth profile. Now all of this built into the cash flow and production targets that we have set for the company, which I mentioned earlier.

Now assets sales, a part of our business model. We have sold $31 billion of assets in the last 5 years, which is a rollover of nearly 15% of our capital employed. At the same time, we are recycling some of that capital into new growth positions for example, exploration and LNG options. Asset sales in the last 18 months were twice more than the positions we have bought.

Now there is no precise target to match these figures, but they do tend to balance out over time. Acquisitions need to complete with organic projects on a profitability basis. This is a tough hurdle, like I tell you, to get the best returns for really our shareholders. Cove is a recent example of this capital discipline.

Now let me turn to exploration. We are driving our resources growth with exploration and bolt-on leads. We have been reloading our exploration portfolio in the last few years, with a buildup of frontier exploration acreage, tight gas and shale plays, as well as maintaining an active drilling portfolio in our more mature heartlands.

We have had 3 successful offshore wells so far in 2012, all in the Gulf of Mexico. Two of oil appraisals confirming the 500 million BOE resources at Appo and at the recent Vito appraisal now confirmed as 300 million BOE resources. Now these should -- both should actually adding -- be adding to our bottom line in the second half of the decade. We have drilled some 50 exploration and appraisal wells worldwide in liquids rich shales and tight gas in the first half of the year. And you can see actually some of the names on the chart. So well results in China gas in the North America liquids rich shale are encouraging, but more work is needed to demonstrate commerciality.

Now I'm also looking forward to some interesting well results in the next 6 months or so. For example, we have the French Guiana and Alaska being drilled over the next 6 months. Now let's just look at Alaska for an update here. We are getting ready to spot new wells offshore in Alaska this summer. A great deal of planning has gone into this program with over 20 vessels to cover the drilling and contingencies. Ice conditions will dictate how long the drilling season will last, with a slower start due to the heavy ice conditions. We are planning for 2 exploration well completions this year, with potential for drilling top whole section on further locations, which we expect to drill next year. Now this is an important step for us in Alaska, in what could actually become a substantial, although long-term province for Shell.

Now before I pass you over to Simon, let me make some comments on North American gas. On the gas drilling side, we are continuing to spend at the low end of our potential range with around 160 exploration and development wells in the first half of this year. This is similar to last year.

Focusing on acreage retention and the lowest cost plays across the country there. We are working on a series of integrated gas options where I think Shell has a very strong credential. We have 0.3 million tonnes per annum of LNG for transport under development in Canada, and we are working on 2 similar projects in the United States, which we expect to launch shortly.

You may have seen, we recently signed a memorandum of understanding with TravelCenters of America to sell liquefied natural gas to heavy-duty road transport customers in the U.S. This is at about 100 sites nationwide. On the LNG export side, we are working with strategic partners on a 12 million tonne per annum LNG project in Canada. The gas supply for this project could include resources from Shell's Western Canadian gas positions.

This includes [indiscernible], where resources have increased from 6 Tcfe in 2008 to potentially more than 12 today, through drilling programs in recent years. We have doubled the resources potential here since we actually acquired Duvernay.

Now we have further natural gas value chain options on the drawing board. This is LNG, this is gas to chemicals, but also gas to liquids. We will say more about those in the future, but I think there is a very strong opportunity set emerging here for Shell. So overall, good progress on the strategy, the development project flow and the broadening out of our pre-FID option set.

Now over to Simon to talk about Q2 results in some more detail and update you on the financial side.

Simon Henry

Thank you, Peter, and good afternoon. As I've said before, quarterly results are very relevant, but good or bad, they're really only a snapshot of performance in what is a volatile industry, where we are actually incrementing a long-term strategy with a rather longer wavelength than 3 months.

So I'll just start with the macro environment. If you look at the macro compared with a year ago, second quarter 2011, oil prices and the global natural gas realizations declined from a year ago, and the risk change reflects some easing of the geopolitical pressures that were actually boosting the oil prices a year ago.

In North America, the Henry Hub natural gas price has essentially halved due to the supply bubble from shale gas. But outside of North America, the natural gas realizations were broadly unchanged Q2 to Q2, some regional differences, but supported by, of course, time-lagged oil price linkages, where gas prices don't yet reflect the fall in the oil price.

Industry refining margins were higher in Europe and they fell in the U.S. and in Singapore, particularly in Asia Pacific. Industry chemical margins rose in the U.S. on the back of tight supply. In Europe, they're underpinned by the falling naphtha price, but in Asia Pacific, again, they remained low due to weak demand.

The overall trading environment for oil and gas has been softer than the year ago, with overall weak demand, but also lower daily price volatility than we saw last year. So the basic message is we continue to see a very mixed picture on overall energy demand and the consequences for results.

So oil demand in total did increase year-on-year and LNG demand remains strong. But European gas demand remains weak due to the weak economic conditions, price competition with coal. In fact, we're seeing coal substituting gas at the moment for power production, particularly in the U.K. And in the Downstream, we do see evidence of a slowdown at the end of the second quarter, and that's as we effectively entered the third quarter with softer industry refining margins in the U.S. and in Asia-Pacific. So still very mixed.

Turning now to the earnings in the quarter itself. CCS earnings can cost of supply work for the quarter, including the identified items of $6 billion, excluding the identified items. The CCS earnings were $5.7 billion and the earnings per share decreased by 13%, 1-3-% as compared with the second quarter 2011.

On a Q2-to-Q2 basis, we saw a slightly higher earnings in the Downstream, lower figures in the Upstream. Cash flow from operations was over $13 billion. Dividends declared in the quarter, $2.8 billion. We're offering the scrip evident again for the second quarter 2012, and the buybacks, which are aimed at offsetting the dilution from scrip overtime, should surpass $1 billion year-to-date this week.

So let me talk just a bit more about business performance, firstly, on the Upstream. On the Upstream earnings, excluding identified items of $4.5 billion second quarter, that's a decrease of 17% versus the same quarter 2011. Weaker oil and gas prices, weaker gas trading conditions. They were the main drivers of the decline and that's about $700 million of the quarter 2 to quarter 2 impact. We did see positive earnings momentum from growth projects.

The deferral of a second quarter dividend payment into Q3 by one of our LNG joint ventures, combined with planned maintenance that we did highlight back in April of 50,000 barrels of oil equivalent per day, greater than we were seeing a year ago. They took around $500 million of the earnings on the Q2-to-Q2 comparison. A lot of that 50,000 was oil rather than gas.

The first half, oil and gas production in total was 3.3 million barrels of oil equivalent per day, and that's an underlying production increase for the half of 4% same as the quarter compared to last year. And the growth comes as a result of the multiyear investments in new oil and gas fields and the programs to increase the production uptime, both of which Peter referred to.

So, comments on Upstream for the third quarter. During the third quarter, looking ahead, there will continue to be planned maintenance, mostly now in Asia Pacific and Europe. And relative to Q3 last year, that's about 25,000 barrel a day oil equivalent impact.

The 3 recent large startups that Peter showed, Qatar and Canada, they produced 360,000 barrels a day oil equivalent in the second quarter 2012, and we expect similar production from these assets in the third quarter. Same as the first quarter as well.

So as you also may remember, the U.K. government announced a tax increase for the Upstream business back in the first quarter of 2011. That legislation has now just been enacted. So we're expecting to see a net charge of somewhere between $300 million, $350 million in the third quarter of 2012 that will be related to the change in the tax basis for abandonment costs in the North Sea.

That's a charge and it will be treated as an identified item.

Turning now to the Downstream. Excluding identified items, the Downstream CCS earnings were $1.3 billion, and that is slightly higher than year ago. Oil products numbers were slightly higher, slightly lower numbers from chemicals. Oil products earnings reflect an improvement in the overall refining margin environment, slightly lower marketing and trading results, although overall market and trading was basically in the expected band.

Chemicals earnings declined, and that was driven by essentially weaker margins across all of the main product lines weaker demand in Asia Pacific than projected. Now we are expecting worldwide refinery and chemicals availability for the third quarter in 2012 to be slightly lower than it was in the third quarter last year, due to higher planned maintenance in refinery and chemicals manufacturing units.

So those are the earnings. Now turning to the cash flow. The cash generation on a 12-month rolling basis, excluding working capital, was some $47 billion. And that included $7.3 billion of disposal proceeds. And over that 12-month period, the average Brent price has been $112 per barrel.

The cash flow generation has been underpinned by strong oil prices, clearly, but by the ramp-up of new projects, some support from the timing of dividends declared across the 12-month period by our equity affiliates.

The Upstream generated cash flow after -- sorry, the Upstream generated surplus cash flow after investment, the Downstream was broadly cash neutral before any payment to the dividend. It's good to see the cash flow that we've been generating, but we are looking for more from the company here, as you know, this is a core part of our strategy and medium-term targets at.

Turning now to the balance sheet. Firstly, gearing sits at 8.1% at the end of the quarter. That compares with 10% at the end of the first quarter, continuing to move lower in the 0% to 30% range. Now you would expect this in the oil price even though it came down still above $100. We continue, and intend to continue, paying competitive and affordable dividends. We've got a great track record on dividends and they are our main route to return cash to yourselves, the shareholders.

You can see the spending levels for the first half of 2012 on the slide here. $11 billion on a net basis, deducting the divestments, but including $1 billion so far this year, approximately for acreage acquisitions, some of which were on the slide that Peter used earlier. Now we are on track to spend around $32 billion this year of organic spending. You can see investment picking up on the projects that we have under construction, 24 major Upstream projects, Peter hand on the map. We invested $8 billion in the quarter. We are on a burn rate for $32 billion for the year.

We will see some of the further buildup in the spending run rate in the second half given the project flow. And as Peter noted, we're moving from a period of bringing acreage in from an exploration perspective to drilling it, particularly areas, of course, French Guiana and Alaska. Now we expect to invest about $1 billion this year on Alaska. And we've now effectively absorbed that amount into the $32 billion capital investment outlook.

We're doing well on divestment. We've reached our $4 billion target for the full year in the first half of the year. I do expect more to come on the divestment side, but we'll update you on that as we go forward.

So that's where we are on the finances overall. We're improving the cash flow both from the macro but also, and more importantly, from the project flow. We have a competitive payout picture and we are showing good progress on the current investment program.

Peter, back to you.

Peter R. Voser

Thank you, Simon. So let me just summarize before we go into the questions. Our performance in the quarter underlines that we are delivering on our strategy. We are making good process -- progress with our strategic seams, that's performance focus, growth delivery and maturing new growth options.

Canada and Qatar are in the delivery phase and we have diversified our development portfolio for the next tranche of work. We are working hard to generate more choice in our pre-FID option set to get the best balance of risk and reward for shareholders.

And this is all coming through in our results, improving financial performance and new projects for the future. Shell adds value through innovative technology, sustainable growth, integration across the value chain and by creating long life returns for shareholders.

And this is competitive and an innovative strategy. With that, let's take your questions. I think we would start off here in the room. I would say ask 2 max at the beginning, if you have time, we go around a little bit more. And then we also go on to the web from time to time.

Question-and-Answer Session

Peter R. Voser

Let me get organized. Okay, Irene?

Irene Himona - Societe Generale Cross Asset Research

It's Irene Himona with Societe Generale. I had 2 questions, please. So Peter, you referred to a multibillion dollar opportunity from improving the operational reliability of the assets. Indeed, you had an incident this quarter at Port Arthur. You had an incident in Singapore last quarter, I think. The U.S. refining has been in some trouble for a number of years. What -- this seems to be a systemic issue and I guess, the question is, do we know what the key cause is? And when you referred to the multibillion dollar opportunity, how can we quantify or think about that? My second question was on exploration. You highlighted a large number of prospects that you are drilling in the second half. Could we perhaps focus on the Chinese shale gas opportunity? You have made some discoveries. You sound quite excited about that. How can we think about the timeframe of commercializing that? And also, longer term, the potential impacts of that on your LNG business. I'm thinking here about the threat to the oil price link in your Asian LNG contracts.

Peter R. Voser

Okay. Thanks for the questions. I think I'll take the LNG and then take the first one and Simon is working with me on China. He can take the shale gas one. On your first question, I have to, in a very strong way, push back on your word systematic. Because we are running a big refinery system and you can have incidents. The important thing is actually that you learn how to fix you know where it is and you make absolutely clear that over years you're actually improving your operational, your assets, your safety and your integrity performance. We have worked very hard on that the last 6 to 8 years, and we have clearly improved and all of our stats, which we also make available in our sustainability report, they're all trending in the right directions, which is a strong improvement over the last 10 years. Safety and assets integrity are key components of our culture in Shell, and I'm very proud that with all the optimization which we have done on the continuous improvement, the piece which we have excluded is safety and the environment and disaster integrity. We have spent more than $6 billion over the last few years to improve our asset integrity. So whilst we don't like incidents like that, they were happening in normal operations. So no plus part of the startup and obviously, we are learning out of them and we will deal with the issues. The continuous improvement is a sum of a lot of different projects and initiatives, and they're not only here to actually lower the costs that would be their own description for that. What they actually generate is more value for the longer-term. Some of them bringing you an optimized cost basis that goes into the billion. If you look at our base costs, apart from the increased production and the increased fees acreage we have, we are still seeing continuous cost takeout across the organization, but we also see a lot of initiatives coming into improve actually in the longer-term the way we can deliver values. So this is a program which will, in my opinion, never stop. That's why it is called continuous improvement because you always work on it. And it's always driven, at the beginning, at least, it's driven from top-down, but it's over time, it's driven by the organization itself because it becomes part of your culture. On the second one, I start with the macro picture on the LNG and then actually, Simon can give the details. On the LNG forecast, which we see across the world and specifically, in Asia, we see a kind of doubling of the LNG consumption between now and 2030. This is driven -- a lot is driven by China, but also by other countries who are now starting to import LNG. In most of these countries, we still have a very low percentage of actually gas in their energy mix so there's quite a huge potential there still. And in China itself, there's only 4% in the energy mix is gas at the moment. And I think the more domestic gas we actually find, the more we will see a switch from other energy sources into gas and into LNG. So we don't see actually the demand slowing down. Now let me also just be clear on this discussion about oil price linked or not linked. I think the market that yen will determine the price. And if you take 3 or let's take a $4 Henry Hub, that gives you $11, $12 landed in Tokyo. If you are not in the spot market dealing at the moment, which is $14, $15, in a normal price environment, there is actually not much of a difference between an oil price linked, what they call, and a Henry Hub delivered into Asia. I think the customers in Asia, they're very keen on long-term, reliable supply, and if they actually get the LNG from big infrastructure projects like an LNG plant, that's actually what they want and what they look for. And therefore, I think you will have a return for those who build these things and that's expressed at the moment in an oil price linked type of formula because what we are replacing is mainly oil exposure in industrial oil and, hence, actually you have the same formula for them is quite interesting. I think we should change our talk and really start to talk about gas prices landed in Asia and then even if a cheaper Henry Hub is actually no longer that far away. And I think that's the way you approach it. And then the other thing is how we are actually optimizing the gas in North America, and we can talk about that later. There's plenty to be done there. Simon, results from China?

Simon Henry

Thanks, Peter. This is a strategic place, let's talk about maybe the overall picture and then specific results. A few years ago, the first development, Changbai, we got up and running with PetroChina, as a result of that. Good relationship. Good operation performance, safety, environment. We have developed a series of further opportunities within China. Initially, with PetroChina, but you will have seen, hopefully, yesterday's press release, we announced first agreed deals with Cnooc, which are obviously offshore deals. One in China and one in Gabon. So Changbai was our first. Yesterday, we announced an extension of the nature of the license in Changbai. And not just in time, but in scope. So additional barrels, different development horizons. But we'll build out and potentially additional resources and additional production from our existing main operated activity. A couple of years ago, we started to look at the onshore tight gas and shale gas activities, as Peter says, the 2 of us spent quite a bit of time on airplanes to Beijing. There are several plays in our portfolio with PetroChina. We have 2 in Szechuan province in the South, Southwest, and we have many CBM opportunities in the North and Mongolia in Jiangxi Province. We are drilling. We spent last year around $450 million. This year over $500 million. We're drilling about -- could get close to 20 wells this year. It's still very much exploration and appraisal. So we're not doing back drilling, it's single well from the pad, looking at what is the scale, what is the nature of the reservoir, what will be the cost to develop, what would be an appropriate development plan. It's looking like it'll be into next year, probably towards the middle of next year before we really have a good feel, particularly on the 2 Szechuan developments, as to what is the appropriate commercial development program. So far, we've had a range of outcomes on wells, good, bad, some interesting. Not quite what was expected, but usually in that sense, better than expected. We don't know yet the full answer to your question. In a year's time, we will. We'll share it as we go forward. There is definitely great potential there. It's a question of how to make it economic. We've not stopped looking for further acreage either. There are several other opportunities in the country, including potentially wet or more liquids-oriented opportunities. And if we're able to mature those, we'll tell you about it.

Peter R. Voser

Okay. Theepan?

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Theepan Jothilingam, Nomura. Two questions, please. Firstly, just focusing on the Gulf of Mexico. I was wondering whether you could just give us a view on the short-term profile there? And then clearly, you're making a lot of progress on exploration with Vito and Appo. What's the aspiration in terms of sort of production level sort of towards 2017, 2018? And then, I guess, there still remains a perception that sort of your short to medium-term growth options are biased to Australia. I was wondering is there a case to reduce that exposure? Or how do you go about mitigating the risk on cost inflation or project execution risk?

Peter R. Voser

Thanks, Theepan. I will start with Australia. In the meantime, you can think about the Gulf. On Australia, indeed, there is no doubt about cost pressure in the country. Now we are active in Gorgon, as you may know, in Wheatstone, active in the sense we are shareholder there and we are driving Prelude at the moment, Pluto through Woodside just came onstream. I think we are quite immune in that sense on the cost pressure, on the Prelude side because that's being constructed in Korea. And therefore, we are not exposed to the labor costs actually in Australia. It will be anchored offshore, et cetera. On the other 2, they're operated by Chevron, so I guess you need to ask them in terms of the cost pressure, et cetera. I would just say from our side, what we have in our plans and what we present to you, and that should actually cover that. Then comes the next wave. Now the next wave, on the one side, we had is Arrow, where we took a very deliberate decision to actually not rush Arrow through. We saw the other 3 projects coming in. The prices were going up, labor costs were going up and hence, we took a decision to, hey, it's also, it's new to us, we want to learn it properly to actually and have our Chinese partner. So we actually taking FID -- so we are preparing FID. We are looking at how to procure, how much we -- how we can actually optimize the use of our wells management joint venture, which we have with the Chinese. How much we can do in modular design later on. So what we are trying to do is really to work how we have done it in Canada a few years ago when the costs exploded there, how we can actually work in a smarter way to keep the costs further under control. Then we have [indiscernible] we have Sunrise, coming as well. I think that's early. We are in the phase looking at the cost there. So we'll see where they go and what solutions we have there. So one of the strategic reasons why I'm quite keen to have options in the portfolio is also, I don't want to get pushed into the wrong development at the wrong time. Now Australia has obviously some advantages because you may actually delay it, which you may not do in other countries because you have permits expiring, et cetera, et cetera. So really, having a rich funnel early on in your maturation pipeline is something which we are aiming at. What we then pull through, that funnel of developed molecules and the plant, that's obviously -- that's where you can't stop and that's where you have to be sure you have the right profitability with the right costs, et cetera, et cetera. In Arrow, when we heard that, for example, one of the suppliers is the EPC contract, for all the 3, and is promising us the 4a team, then we get very suspicious, because you normally don't get 4a teams, you may get 1 and then you pay the price for the rest. So we're trying to read all of this and slow down where we have to slow down. So Australia is a key component for our growth but we will not over do it if we aren't getting the right profitability out of it. On the Gulf?

Simon Henry

Gulf of Mexico, just on the context of deep water overall, the constraining factor is basically rigs. How many rigs can you operate safely and cost effectively? A year ago, we were operating 12 rigs, we're heading towards, by the end of this year, 16 rigs. This is a global number. We're bringing onstream some new rigs part owned or 10-year leased by Shell that are so far performing extremely well early on in their life cycle. At the moment, 6 of those rigs are in the Gulf, one is in French Guiana, one is in Brazil. The rest are out elsewhere. By the end of the year, we'd expect 8 floating rigs, 4 platform rigs, potentially operating in the Gulf. So 11 or 12 drilling operations in the Gulf. So significant step up, obviously, compared to where we were during the moratorium, but even compared to where we were before the moratorium. We've just had Caesar-Tonga come onstream. We have Mars B going very well. That was one of the pictures that Peter showed in terms of construction. Our production in the second quarter is about 180,000 barrels a day. Now that's a low point. It's a low point for 2 reasons. One, we have project as we've turned the corner post moratorium effects, but we had a lot of downtime in terms of the quarter itself. Going forward, we'll have less downtime and we will continue to turn the corner because Caesar-Tonga is on. We're drilling the in-fill wells around Ursa, around Mars, Perdido is still in a ramp-up phase. So it will flow forward with growth. Mars B is the next big boost coming on in a couple of years’ time. That will then be supplemented by Vito, Appomattox and Stones. Vito and Appo get bigger every time we look at them. So to be honest, the FID has got a little bit further out but for good reasons, we're trying to work the most appropriate development concept, how big a facility do we need to work. And the same is true with Stones. So which one gets to FID first? Not sure, it could be Stones. But over time, from that 180 sort of minimum, we should do considerable growth just in the Gulf of Mexico. But those projects will have to compete, we hope, with French Guiana, we're doing appraisal in Brazil. And 1 or 2 of the other deepwater activities around the world. So our limit is going to be number of rigs and how we choose to use them. But so far, some good progress this year. And hopefully, some exciting news to come later in the year, because one of those rigs is on its way to Alaska, of course.

Peter R. Voser

I'll take one more in the room and then I come to you. Yes?

Iain Reid - Jefferies & Company, Inc., Research Division

Iain Reid from Jefferies. A couple of questions about your North American gas assets. We started to see some companies write down the value of their dry gas assets in the U.S. And I'm just wondering how comfortable do you feel about your carrying values, given the acquisitions you've made in the past, future gas prices you can see on the screen? And secondly, on LNG export, there's quite the queue of proposed facilities in advance of anything you might put in there. And if you add up the numbers there, you get to quite a big number in terms of what could be exported from the U.S. I wonder how much comfort you'd have from the U.S. government about if you go in there at the tail end of this, whether you'll get approval for LNG export scheme or whatever magnitude you're thinking of to deliver a few years down the line? What's the U.S. Government thinking about this? Because obviously , you don't really go ahead if you don't feel you're going to have the capacity approved.

Peter R. Voser

Yes, okay, I'll take the second, do you take the carrying value one?

Simon Henry

The question's really about the carrying value of the North American gas sets that we've acquired over the past few years, and we've talked about $17 billion. There's a bit more than that now because we've been investing further in them on the 40 Tcf asset base. We do an impairment review erosion review every third quarter. So we're about to enter this year's program. We've been using $46 for that, the same way that we talk about investment decisions that we make. Last year, everything was fine. What will chance this year is not so much pricing outlook, I suspect, it's what's the drilling program outlook because we've shifted the drilling now 20 rigs onshore I think in North America now on liquids rich activity, it was, I think, 5 or 6 a year ago. And that's halved the gas drilling activity. We're doing very little, for example, in Wyoming or in Louisiana at the moment. Only gas drilling is in Canada and Marcellus. I don't know what the outcome will be. We'll just do the normal work looking forward, long-term, gas prices for the Q3 results and we'll let you know at the time. But I can tell you that in the second quarter, despite the current gas price, all our basins were actually operating on a cash positive basis.

Peter R. Voser

On the export opportunities, first of all, as you know, we're working on Canada. So that's -- we are optimistic there. So that's clearly moving in the right direction for the 12 million tonnes. And we signed up a pipeline builder et cetera, et cetera. So with our partners, we are progressing there. It's still has to go through permitting processes, and that takes some time though. FID is not going to be tomorrow, it will take its time. If we then move southwards. I think the base assumption here is there will be LNG export. The question then is how much. If I take it from a very strategic point of view, I think you will see in North America, specifically in the U.S., that they have got an energy situation now, which could bring them pretty close to energy independence over the next 20 years, if the Gulf, if Alaska, if liquids rich shale, if the cash actually takes off and is kept in the country, replacement of coal, driven power generations through gas, et cetera, et cetera. But on top of it, it could also actually bring a lot of manufacturing industries back into the country, petrochemicals industries back into the country because you have achieved source of a feedstock. And that's all equals jobs and revenues in the U.S. So I think whoever is in charge of the energy policy, one station what they want in the U.S., you make sure that you also want one in Europe at one stage, we'll have -- we'll look at these as on the one side, as a pure Energy Policy, but on the side, also about jobs and revenues and actually having, let's say, industries back home. So therefore, I think you could think of a very high number of LNG exports. I think the market will actually drive the right number at the end from an export point of view on the gas side, but also from a demand point of view inside the country. Governments will give you, most probably, incentive schemes, tax incentive schemes to invest in the United States. So therefore, I think there will be a natural kind of cap, most probably not enforced by the government, but because of message they take, it will get to one. Therefore, I think I would agree with you, if you have 10 or 20 in the pipeline, you most probably need to be in the earlier half rather than in the second half in order to have some certainty on that. Now we are working on LNG projects also in the United States. We will inform about that in -- going forward. But we are looking at that and make it to you very clear, we are looking at that not just somewhere in the country, but also at the Gulf Coast. And we are looking at whatever opportunities we have there and we'll see how we can actually link that into our very well-developed gas chain strategy, which we are pursuing, which LNG and transport to liquids to chemicals LNG export and we will then determine how we move, actually, the molecules around. One from the web.

Operator

[Operator Instructions] The first question comes from Jon Rigby from UBS.

Jon Rigby - UBS Investment Bank, Research Division

Two questions, one on the Upstream, one on the Downstream. On the Downstream, I know you've done an awful lot of work in the restructuring of the business, buying, selling and improving refineries in particular. But you just don't seem to be getting a huge amount of leverage in terms of your earnings or your units earnings. Is that a fair observation? And if it is, what are the moving parts going forward that you think will restore both earnings and cash flows or something more acceptable? And the second is just on your U.S. Upstream earnings. Can you give a bit more insight into the moving parts that drove what looks like a very low earnings figure this time around. I'll take the points about low levels of Gulf of Mexico production. But can we just go into a bit more detail about what's happening there?

Peter R. Voser

Thanks, Jon, for the questions. I give the Upstream to Simon, and I will handle the Downstream.

Simon Henry

Upstream first? Thanks, Jon, for the question. The Upstream earnings were impacted by a series of relatively small things, some of which are one-off, some of which are short to medium term and some of which are potentially long-term issues, all working in the wrong direction in a given quarter, some of which were already flagged into the market. So I'll start with some of the short-term one-offs. The production maintenance that we talked about was primarily in the U.S. It was on oil projects, and it was in a period where, obviously, margins would've been good. Shorter-term impacts, we see in Canada oil being produced, but they realized bitumen and synthetic crude post upgrading prices. The bitumen was about $65, the synthetic crude about $80. So an additional discount to WTI of around $15, and that's widened from more like $5 a year ago. That -- some of that is a short-term issue, some logistics constraints in the Chicago area, getting that crude out of Canada and into a refining network. Some of it is a medium-term issue because it's WTI linked. But long-term, it's less of an issue because those distributions systems will even themselves out. We did see increased depreciation in the quarter, significant amount of this is to be expected. It's new production coming onstream, for example, in the Gulf and early on in a project, particularly deepwater project, you do see higher unit cost depreciation. That unit depreciation goes down as you prove up more reserves as data on the reservoir comes through. The same happens onshore. It's not too dissimilar, it's just a lot more wells, smaller numbers, but they add up to a material impact. We are moving those rigs from gas to liquids rich shale. We're therefore, not proving up as much reserve in the gas activities as we might have hoped to at pace. And that has led to high unit depreciation, not only on the gas but also on the early liquids production. So you're seeing probably for the next year or 2, high unit depreciation until that settles out as we recognize more reserves through more drilling in the basins we focus on. We've then got more exploration and more feasibility expense, more seismic expense and more feasibility expense on the project Peter just talked about, LNG, GTL, gas to chemicals, you can't do the study and the design work without spending some money. That's all coming through in the same quarter. It's not one-off. It won't go away, but it is good leading to future opportunity. So a combination of all of those things and each take only $50 million, $100 million out relative to expectations, that's what leads to the results you see. So fundamentally, it's a cash positive business. You can see the cash flow coming through. And it is a business in a strategic transition. It was a quarter in which most of the wind blew in the wrong direction. Hopefully, that helps, Jon. Peter?

Peter R. Voser

Thanks, Simon. On the Downstream, we have worked on the Downstream over the last few years in order to get to a portfolio, which we see as a portfolio to go forward. That included significant downscaling of refineries so we sold significant barrels there or we closed them and changed them into depots. Some are still in the making and we have talked about them. Some will change over the next 12 to 24 or 30 months. We have also significantly actually purified our marketing portfolio. Sold out of smaller countries where we have no economy of scale in order to actually take costs out and the capital out. So I think we have the portfolio now. That is still the real driver on continuous improvement because we need to bring now some of the assets back up to top quartile performance. That's where the focus is at this stage. And that in itself also then takes costs out. And we have seen, for example, when you look at some benchmarking from the market, which we see and the Refining business is pretty much benchmarked, that we are actually now, our operating costs, we are now getting closer and closer to the first quartile. So that is all there. If I take the marketing and the trading business, quite clearly, the trading is really linked to the Refining business. I personally don't look at the Refining business in isolation. I look at the chain, including trading, including our fuels B2B business because that's, and our retail basis. That's where the molecules are going. And therefore, we look at that strand. Now if you take that integrated value chain, quite clearly, in the second quarter, we saw that compared to last year's second quarter, there was a lot of volatility in the oil market, in the product market because of Libya, for example. This was different this year. Therefore, we added less value by using our refinery molecules into the system. We had obviously a decreasing pricing environment whilst we cap prices, the volume at the same time was coming down. So Q2 was a quarter which where the adjusted from a high to a lower oil price is not a lot of volatility around it from a trading point of view. So going forward, this not about reshaping the portfolio more. It is actually operating at the top quartile performance in order, actually, to get our performance in line with where we want to be, where we actually can generate the necessary returns. And the cash flow, now on the cash flow side, that's the piece which I don't agree entirely with you that we need to further improve that. If you look back over the last 4 or 5 years, I think the Downstream cash flow is actually a key piece which is underestimated. We had most of the time, we had in the billions cash surplus, Downstream was one of the strong contributors, actually, to the dividends over the last 5, 6, 7 years. So this is not about generating even more cash out of it. Obviously, if you improve our earnings, that will have an impact quite clearly. But it's about the operational performance, where I'm not entirely satisfied and the base costs are still being worked and we had good progress in Q2. Now the one piece which you always have to exclude, but I don't take that as an excuse, but just as a number that you know, in the whole Refining business, we had some $200 million of foreign exchange as well, which obviously impacted our refinery results in Q2. But to be very transparent, you benefited on the cost side on the marketing side because you had a weaker Euro. And therefore, we have a lot of euro costs that helps us actually in that sense. So this is not a construction site, which we need to change, this is about having the right portfolio and working the operational excellence into the portfolio. Thanks. Do we have another one? Let me take one and then we come back to Lucas.

Operator

The next question comes from Robert Kessler from Tudor, Pickering, Holt.

I just wanted to ask you a bit about the CapEx. If I understand correctly, the $32 billion previously did not include the extra $1 billion of potential for Alaska. Now I think you said it does include the Alaska. So my question is, is that accurate? And what has moved out to make room for that?

Peter R. Voser

Thanks for the question. I think it's correct, your understanding. It's now $32 billion. Where's the $1 billion? I would just say we were doing more or less the same activities. There is maybe some rephrasing in it, not the bulk of it. But we are clearly also seeing some impact through our exercises and through our initiatives, which we are doing and actually getting some of our procured costs down. We have a very strong drive there and in all of our enterprise framework agreements, where we actually procuring costs from our suppliers. We signed hundreds of them and actually, we got between 10% and 25%, 30% lower prices. So discounts on it. That's, in a way, also flowing back in. Then as I've said, some deformities also happening and you may remember last year, we had a very strong rephasing from 2011 into 2012. And there also most probably, we assume something similar to happen this year, and that's not entirely the case. Lucas?

Lucas Herrmann - Deutsche Bank AG, Research Division

So can I just come back to the Americas and 2 questions. The first goes back to the statement you made when you went to Canada in 2010. You talked about production in the region could reach 1 million barrels a day and you talked about the intent to invest potentially $40 billion over the '11 through '14 period. Now I can see the $40 billion going in, $15 billion has gone over the last 1.5 years. So you're in line there. But I just wondered how you felt about the 1 million, or the approaching 1 million-barrel a day stages? And secondly, going back to Jon's question, if I look at the capital that you've now got wrapped up in the Americas in total, it looks like it's about $85 billion, $90 billion capital employed. On which even if I start adding back the numbers you're talking around this quarter, I'm looking at something like maybe $2 billion, $2 billion or so of net income. How do you give me confidence that the returns in that business are actually going to move to anything near respectable because it's not the way things appear today and I hear what you say on cash and cash flow. The problem as I can't see the cash flow numbers on the Americas Upstream. I just get the 2 lumped together. So I guess the question is twofold. Firstly, CapEx is going in but are the production barrels actually effectively cash coming out? And 2, is just the volume of capital in and the absence of profit that's coming out? And when does that actually turnaround?

Peter R. Voser

Simon? He asked you to answer.

Simon Henry

Thank you, Lucas. Thank you for reminding us of previous statements. I can't confirm OE numbers, but you're not far out in terms of the -- or certainly what we had done in the past but the capital employed is a very significant part of the total 210. Therefore, the current return on capital is somewhat lower than we might seek. We knew this was going to be the case because of the nature of the investment program. And I'll start at the end, CFFO transparency in the quarter just over $1 billion, came out of the Upstream Americas, excluding working capital. A bit less than in the first quarter. And that's a quarterly number. So second quarter number. And will presumably increase, given that all the one-off factors I previously referred to. Upstream Americas, you have to think of is not one business each, each of the different activities has different profile. The heavy oil is now solidly profitable, solidly cash generative. And the return on capital is okay. It can improve with some of the programs Peter talked about. But it is improving. Our unit cost of $10 a barrel lower today than they were a year ago. So we're down below $40, we're a benchmark top quartile levels in that mining activity. We've got debottlenecking opportunities. We have opportunities to the steam assisted Carmon Creek to grow. But we won't be putting a lot of capital into that business relative to the rest. The deepwater business, just talked about, with whom we've hit low hopefully at 180, that has significant growth potential from the things I talked about. Again, it's solidly profitable, good returns, high oil price upside. So the issue is not everything across the Americas, it's primarily the onshore activity. That was also the main driver of the production target. So in the 2 areas I talked about, heavy oil and Gulf of Mexico, deepwater, and Brazil as well, which also fits the Gulf of Mexico profile, we're pretty much on target for what we said in 2010. The big difference is onshore, gas and liquids rich shales and in fact, liquids rich shales didn't really feature in the discussion back in 2010. So we've cut back, I would say, we were planning by now 50 to 60 rigs on gas drilling alone and a rapid development of gas. We've now dropped below 20 and even in that, there's less of it going onto development than scale on to appraisal, which is preparation for a recovery in gas prices. There's no point in producing now if you can prepare, sit on, and produce in the future. So our actual level of activity is about a quarter of what we expected in the gas. But the molecules are still there. Most of them are in Marcellus and Western Canada. And the break even there is at or heading towards $3 economic break even. Cash break even is more like $1.50 once you're up and running. The switch to liquids rich shales now we're in immature basins relatively other than Eagle Ford. So we're up about 10,000 barrel a day production there now. But it will take some time to come through. We'll only see momentum there in 2013. How much momentum will depend on how successful the exploration appraisal work that we're doing. Most of the basins were named on the earlier exploration sheet but basically, it's in Western Canada, in or around Duvenay and the Canadian piece of the Bakken. It's in Mississippi line, in Kansas, in the Utica, and in Eagle Ford in the United States. We will have drilling later this year in the Neuquén in Argentina in the Vaca Muerta play. And in general, on gas and drilling activity, we've also shifted some emphasis outside the U.S. So Ukraine, China, South Africa, the big gas players, is where we may well -- we've only got so many drilling engineers as well. So it will be less in the U.S., it will be more developing. So whether the 1 million barrels a day will get delivered at the same time is a moot question, whether we deliver very significant growth around the world from a combination of that which is in the Americas and unconventional activity globally, I think very much on track. In fact, the portfolio is a lot stronger than it was 2 years ago. We would expect to see returns in the Americas overall continue to carry the weight of that capital employed for some time now. There's little we can do other than write off huge amounts, and that's not in the plan. But it is -- between now and the end of the decade, it's the primary engine of growth for this company. And I haven't even mentioned French Guiana and Alaska, both of which could potentially absorb capital, but be looking at production by the end of the decade.

Peter R. Voser

I think he was inviting you to write it off, Simon. And you get a better return, I think, is what he was [indiscernible].

Alastair Roderick Syme - Citigroup Inc, Research Division

It's Alastair Syme from Citigroup. Can I -- it probably sounds catchy, quite a similar question. If you look at the $50 billion of cash flow, I know I'm sort of giving you round numbers '12 through '15 at a $100 oil, and you try and sensitize that for sort of $3 gas and $15 Canadian discounts, is there a big delta that we need to be building into our assumptions, because we're kind of at $39 billion today. So I'm trying to reconcile those numbers in my head?

Simon Henry

The 39 -- thanks Alastair. The 39 is a 12-month period, in which we're still ramping up. Gas, there is a sensitivity, but it's not many, many billions. In deepwater Gulf of Mexico is probably much more significant in terms of will we or won't we deliver projects we spoke about earlier. The Canadian one, it depends how sustainable was discounts prove to be. We expect logistical constraints to progressively be removed, and we're taking part in some of those whether it's a reversal of pipelines in the U.S. or the construction of new pipelines from Canada further South. So by the middle of the decade, we'd expect that all the discounts to have compressed. The question is how quickly will they compress? And it's not a hugely material factor, but it's one we need to manage carefully. Peter, is there anything else you would...

Peter R. Voser

I think more in a general way, we have to -- the $200 billion or if you divide it by 4, then your rough number at $50 billion. We have clearly said that from a gas point of view, we would expect to be in the range of 4 to 6 somewhere in 2015, that may not happen that's what Simon just said, where the refinery margins will be, we will see by then. But I don't think -- I would still say we are on track to deliver that. There are some challenges in there, but that's fine. But we are on the way to deliver this. And as you know, cash flow is to key target, which we have across the company and that's where the focus is. So we are on these targets, some challenges. But we are exactly 2 quarters in at the moment. So there's another few years to come. So I go back to the web and then I'll come back to you, yes?

Operator

The next question comes from Jason Kenney from Santander.

Jason Kenney - Grupo Santander, Research Division

Two, if I may. Can you confirm that you're pursuing the position in Shtokman? And if so, what it is that you find attractive about that asset or a potential role in its development? And then, secondly, on East Africa. I appreciate your comments on the capital discipline showed by withdrawing from Cove [ph]. But do you still see a material position for Shell in the current discoveries offshore Mozambique or otherwise in that region via M&A? Or maybe even organic pursuit?

Peter R. Voser

Okay. Thank you very much, Jason. I'll take both of them. Russia, we delivered, so far the only sub-arctic LNG play. We're very happy with Sakhalin. It's going very well. Producing more and generating more cash. [indiscernible] gas from our Japanese partners. We also have [indiscernible] producing, that's also gas from now and we have been very open that we would not be against further investments in some projects, where Shell can add value there are various ways of doing that. And therefore, we always look at options. But I guess you would expect, I will not confirm the questions regarding Shtokman. I will confirm that we are interested in further investing in Russia and the recent changes in the tax systems or in the tax schemes, either arctic or tight oil or tight gas, thus obviously give some more leverage or some more opportunities and a clear drive from -- to President Putin to more investments in Russia may also open up some avenues. So interested, but this is more or less the same answer, as for East Africa. We have a very rich portfolio. We have plenty of projects in the pipeline, either on the construction or in the pre-FID states. They all -- whatever we do in the future, has to compete against those. And then we will either bring them in and kick something else out, or we may actually develop some of it later on, as I have said. And the same would apply for Russian projects like in East Africa. And let me first say in East Africa, we have -- not it in Mozambique, but in Tanzania we have some organic plays, which we are obviously -- that's on the exploration side is also on the map, which we have shown. So that's one avenue. In totality, the LNG project, which we have across the world, if I start to list them, you will see that we have plenty of things. So we already talked about those in Australia a number, Canada we talked, we also have obviously -- in Indonesia, we have a body. So there's plenty of things already -- and plenty of things which we are still evaluating. Now East Africa is an interesting province, it's a big resource. Needs, obviously, skills, which can do Upstream, Midstream and Downstream. Therefore, is an interesting environment. But the valuation has to be right and that's where we took a view on cove. We took a view on the valuation but we also took a view on the process itself. And therefore, we will look at other opportunities if they come along. And if not, I think we have a rich portfolio already. So we'll see what we do. Any questions inside, I said back there first, and then there is one -- I think more on the way. Four in here. I just want to make sure I don't forget the webcast.

Hootan Yazhari - BofA Merrill Lynch, Research Division

Hootan Yazhari from Bank of America Merrill Lynch. Just coming back to your U.S. business, as much talk of shifting the focus as many people have away from dry gas to liquids rich acreage. But there doesn't seem to be a lot of talk about how NGL liquids are really suffering on the pricing side and realizations there continue to come down. I mean, is there any chance of this derailing your plans? Or indeed, pushing you towards more capital intensive moves down there to actually really realize value from that portfolio as in moving more into petrochemicals, more into GTL, more into sort of LNG distribution onshore? Anything like that? I mean, I'd love to hear your thoughts on that.

Peter R. Voser

Yes, thanks for your question. Quite clearly, the way I would describe our strategy at the moment is we have got some liquids rich shale, but we have a lot of gas and we have got stuff which we see in between. What we are looking is actually to change the exposure we have to some cheap prices into exposure, higher up the value chain. And there you have various ways of doing that. And we are firmly already in the business of pushing LNG into transport. In Canada, we are doing that in the U.S. and by the way, we do the same. We're starting in China, we are starting in Europe on the same. So that's a business model which is coming. It's really bringing Upstream and Downstream together because you need the customers on the Downside because we know them from the retail business and from the B2B business, and you bring them together with Upstream. So that's really taking advantage of the differential between Henry Hub and diesel at the end of today. That's one. So we're driving that. And the same in that similar area is actually for shipping. So we are running bigger projects already in other parts, not in North America, but we are also looking into that at the moment, where the shipping industry will replace diesel engines, with LNG & gas engines, so that's another area. And the next one which we are looking into in Pennsylvania is to take the gas into chemicals. So this is clearly a cracking route, which gives us higher exposure from a value point of view. We are looking into that and we have identified the site. Now it's a scoping exercise, et cetera. The next one we talked already, which will be LNG export and LNG consumption in any other areas inside the U.S. And then the last one will be gas to liquids. That's what we just built in Qatar, can we do the same in the U.S.? Where would we do it? How big it would be? How are the economics? How expensive will be building something like this? Because one of the issues you have, obviously, in the U.S. now, it could lead to a cost explosion, let's say, for example, around the Gulf Coast because everything is being built there and therefore, we'll take a view on that and we will also take a view on how we time this. But clearly, a strategy to get a cheap feedstock into something more value adding is something which plays to our strength because we are an integrated company. We can develop these things. So that's where a lot of effort is being spent at the moment to figure out in how we want to use the molecules, which we have, the resources in the ground, how we want to use them, how much we want, for example, to buy from the markets rather than use our equities. These are all the things, which we are thinking about at the moment. And then we will let you all know the way we develop this, but we have, as Simon said already, quite a sizable team now in the U.S. looking at that. There was one hand somewhere here, and then I'll come back to you, sir.

Neill Morton - Berenberg Bank, Research Division

It's Neill Morton at Berenberg. Two Upstream questions. The first one East Africa, the second on the big 3 projects. Almost forgotten there. You've recently introduced the concept of certain net CapEx selling assets to buy assets. When you were bidding for Cove, I think you actually linked it to the decision to sort of farm down a Prelude to balance the cash in cash out. Given the fact that the cost of entry into East Africa is likely to be in the several billions of dollars, do you envisage offsetting via disposals? Would you envisage using the balance sheet to build the position there? Or are you agnostic? And the second question in the Big 3 is, it you mentioned it was 360 in Q1, Q2 and Q3. When do you envisage the combined projects reaching plateau?

Peter R. Voser

Okay. I think on the first one really goes into portfolio management. And we're using Prelude as an example. We brought impacts, for example, into Prelude and impacts brought us into [indiscernible] in Indonesia. Both are floating LNG developments. So most probably you can add one and one together why this has happened. So clearly, we are looking at these types of things. I said before, we sold some $12 billion of assets, where we made 6 as acquisitions. But I said you cannot always think that we will match this all the time one-to-one. But there is clearly a strategic thinking here, and this is when Simon and I discussed these type of proposals with the businesses. They always -- when they come and want more CapEx they know, especially on acquisitions, they already know we better bring something which we also can sell. Because there is a dimension here that you just don't want to increase, let’s say, your human capital you spend in all of these projects, there is a limit how much you can do. There's a limit from a financial framework point of view. There is a capital discipline which you want to maintain. You don't want to spread yourself too much around. So that all comes together. But I don't want you to walk out of here and say, they will always match 2. They are, over time, you may have been -- we may go a little bit longer for 2 years and then we go along on the other side for 2 years. But there is certainly a portfolio optimization game here happening. On your other question, quite clearly, we gave you an outlook into Q3. With the maintenance, which we are doing in Pearl to adjust completely the 2 trains and actually take full advantage of the slate of products which we can run now as we have proven all the technologies we have ramped up. And my expectation is that, that is pretty much done during the third quarter. So we should hopefully, by then, kind of go into the fourth quarter and get after the run rates we are aiming at. Now you have to be careful on the oil Sands because in Oil Sands, there is always a capacity issue depending on which ore grades you're actually digging through in your Oil Sands. So that's why we normally say that's the capacity you can reach depending on what oil percentage you have there. But there, we are talking about a few thousand barrels rather than 100,000 barrels. So I think the second half of this year, we'll see all of these 3 projects then becoming really fully operational and we will optimize the products later on an ongoing basis.

Martijn Rats - Morgan Stanley, Research Division

It's Martijn Rats at Morgan Stanley. The last time we were in this room, we all had a lot of questions, why the dividends didn't go up more than it went. And I think it's fair to say you expressed some caution and conservatism. Now we're having a quarter where Simon runs us through a list of a few things that sort of seem to going against the results. And it sort of makes you wonder whether sort back 6 months ago, you were already thinking about perhaps some specific things that you might need to face say through the year, where you might -- what are you thinking about? There's always something that we need to anticipate. I was just wondering sort of in retrospect, you can sort of comment on how that discussion went? And how you see sort of that specific aspect going forward? On top of that, I have one more smaller question. It seems to be a few headlines on discussions with Interoil in Papua New Guinea? I was wondering if you could sort of elaborate on that?

Peter R. Voser

Yes, okay. I think, as it is dividend, they both go to Simon. But let me also just say something from [indiscernible] the discussions with the board are very simple. They are on dividends. They are long-term, and we have a policy and we take a long-term view. So short-term macroeconomic and assumptions do normally not play a big role because we really take a long-term view. But it is true when we have the first quarter, I was not very optimistic on the economy. And I was very clear that I see the world going into a slowdown, and that has happened. Now on your second point, which is do you foresee some changes over time, no, we don't. But we also emphasize in a very strong way, quarterly results, and Simon said this in his part, they're a snapshot and we have this interesting situation with this dividend from this LNG joint venture. If that comes in 2 days earlier or later, does it really matter to us? No. But you can have a big miss in the market, and that could be a problem there. So I think where I sit, I take us through the quarter view, a long-term view, but from an operational performance point of view, clearly, every month, the results need to be delivered. But I can tell you, if you have got more security issues in Nigeria, our production can go more up-and-down and that can wipe out growth. And that's actually not what I want to talk with shareholders. I want to talk how we actually deliver the value in the long term. Now over to you on Papua New Guinea and the rest of the dividend.

Simon Henry

There's probably only one thing to answer to dividend, while we don't let the macro drive it entirely, we did have some concerns about where the macro might go 6 months ago. Peter was on record saying exactly that sometime in June, I think, 3 days later, the price dropped $20 to $90. So we thought, if it stays there, dividend will be off the discussion. And so I think the market's more concerned about that linkage than we might be. PNG, there is gas, there is an intent for LNG projects from the government. The government we have been talking for a couple of years now. They announced last year that we were a preferred partner because of the capability they want to bring in to the country, large project developers, people who can develop markets and local capability. So yes, we've had discussions with PNG government. We've had discussions with Interoil from time to time. And I can't say too much about where the discussions are at the moment. Yes, we're interested in a project. Yes, it must meet exactly the criteria that Peter laid out to compete with other LNG options. We don't actually know yet whether that will be the case. There is a new government election process in progress at the moment in the country. As they come out of that, confirmation of fiscal opportunity and where Interoil fits in the government thinking will enable potentially a project to go ahead there. It's very difficult for us to say more because it's still quite uncertain at the moment. It's an attractive play and the same effective geological trend that we're in, in Australia and now in Indonesia. So it's one we think we can add a lot of value to provided the other conditions are right.

Peter R. Voser

Okay. I think I'd take one from home web and then a last one in the room. So we have more than one hand up in this side. So let's go to the web.

Operator

The next question comes from Ken Ménager from Market Securities.

Ken Ménager

Can we have an update on the measure of the [indiscernible] shares, please?

Peter R. Voser

Sorry, could you repeat the question?

Ken Ménager

May we have an update as to the measure of the [indiscernible] shares, please?

Peter R. Voser

Yes, I'll leave that to Simon.

Simon Henry

It's quite a quick update. I think I've indicated earlier, this is really an issue in the first instance between ourselves and the Dutch government. It's fiscal constraints as a result of how the company came together in the first place. Unfortunately, I think as we last stood here, the Dutch government is no more. They're in that period of taking 6 months to arrange an election. And last time, it took 6 months to arrange a government after the election. So we're not actually expecting productive discussions on this in the rest of the year. This was a slightly flippant answer, I think, to be honest, the Dutch government has more serious issues to consider at the current time, whichever of the parties happens to be in power. So it's difficult to see us getting the priority and they're doing a pretty good job in the circumstances.

Peter R. Voser

Okay. I'll take 2 in the room and then we stop. There's one here and there was a hand there.

Richard Ivor Griffith - Oriel Securities Ltd., Research Division

Richard Griffith from Oriel Securities. Just coming back to your 4 million barrels a day target you talked about by 2017, '18. Throughout the course of the afternoon in the Q&A, you've mentioned quite often issues of costs, whether it's Australia, reconsidering the FID some of those big projects. You've mentioned costs around the Gulf of Mexico, you've mentioned rig availability. So at what point does these issues accumulate to a point where your project FIDs then effectively push your target out or it becomes eroded? And the second one is just coming back to the Downstream issue and the improvements of the operational side of it. I mean, how much of this is related to say a structural issue or an age-related issue? And how much are you going to have to spend to get those 1% improvements in availability?

Peter R. Voser

Yes, I think the second one is a very good question. And it's really where you -- where machines are where they are and these are obviously historical decisions you have to do. We are very much looking at your point. So the target is not to get every refinery into the first quartile or across all the benchmarks. You get them actually there where the current configuration does actually make sense to get to. Because you cannot just drive everybody up there because in between, there might be a $1 billion of investment and you would never do so you expect somewhat the performance in that sense. But because you want to have it from an integrated way, you want to have it for your marketing assets, you want to have some coverage of volume, you accept actually that machine. So I think there is a very sophisticated way the way we look into it and how we actually approve gross, we call it gross CapEx in the refining system. And that has a very -- a much higher profitability requirement than most of the other areas which we have actually in the system compared for example to Upstream, et cetera. So that's the way we're trying to steer that. Now on the 4 million, I think -- it goes a little bit back. I always say, 4 million is a long-term target that I can mobilize and drive the organization for growth. But we are not chasing just the absolute number of barrels. We are chasing the best returns and the cash flow growth. Having said that, we are very keen to have enough options in the pipeline that we can achieve our targets which we have and having a flexibility if costs go up in Australia and in -- let's assume for a moment in Canada again, that you have got other areas where you actually can push things in. If you go back to the chart which we have in here, where we are actually doing exploration work at the moment. You see a vast variety of different countries and different regions, which should help us to offset some of that. But you can't be really sure that we are chasing the cash flow growth. But in order to get your engineers out of bed, you also need to a little bit have a volume growth, but you need to steer it in the right direction.

Rahim Karim - Barclays Capital, Research Division

It's Rahim Karim from Barclays. Just a bit of question on the game changer that is Alaska. A few headlines suggesting that obviously with the ice, that drilling might be delayed there and then also, a few more inspections required before drilling is allowed to start. I was hoping if you could just give us a sense of when the ultimate deadline is if things don't start to go -- actually we don't see any activity going ahead in Alaska? Whether that's actually an opportunity or not? And just perhaps how long it will take for the first couple of wells to be drilled, when we could expect some results? And if worse comes to worst, you aren't able to drill this year, what your action plan will be and how we might take that forward?

Peter R. Voser

Okay. Let's start with the ice. That's the one thing which we don't control too much. Normal drilling season would start mid-July in Alaska. This year, it's later, so we expect the ice to be gone most probably within next 2 weeks. On the permitting side, there's some certification of the containment system, which we are working at the moment, so that's together with the Coast Guard. This has more to do that this is a containment system, which is barrier number 4 or 5. And it's the first of its kind which has been built in the world, which stretches also the Coast Guard a little bit from a permitting certification point of view, and we are working together there. So I think, we are working our way through that. So as there is delay, we have got downtime. Then I think typically, the window would be it's a little bit shorter on the [indiscernible] because the ice comes earlier back in that sense compared to the Beaufort. That's one thing to consider. And then there is also on the Beaufort, we have to stop drilling somewhere for when the whale hunting is ongoing, but that's a concession which we made with the local communities. So having said all of this, we are aiming for the 2 wells to be drilled and maybe some others to be prepared for next year. We have already applied for more so that we can actually continue next year to drill. So we should not go through the same permitting process because we already have applied them. Some of the permits you need to renew yearly. So I think, we are on the right track. We have done everything, great cooperation with all the regulatory bodies, and we are now just getting to the end of the certification and all the rest of the vehicles and I always say to Marvin is now also the Captain of an armada, because he has more than 30 ships out there. In order to actually drill the 2 wells, which are, as you know, there is shallow water, low-pressure, it's actually not the most difficult thing to do. But fine, we have all of that prepared. And so I think that's how it is working at the moment. Drill this year and should drill next year in that sense. It's the thickest ice which we have had for the last 10 years, and that has delayed it somewhat now. But otherwise, it's going okay.

Good. That's it, I think. It's all okay, good? So thank you very much for coming here. The first quarter results will be announced on the 1st of November. Now for the analysts in all of this, we are hosting a shareholder engagement covering global gas and especially Asia Pacific on the 14th of November in London and on the 15th of November in [indiscernible] New York. And I hope you will be able to join me and some of my team for one of those 2 events. And 2 weeks earlier, Simon will tell you what happened in the third quarter.

Thanks for turning out. I wish you a great Olympic fever over the next 2 weeks, and I hope traffic is acceptable for you. Thank you very much. Thanks for the web as well for listening in.

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